Numerical simulation of underground hydrogen storage in a Louisiana saline formation: a feasibility study

Document Type

Article

Publication Date

11-26-2025

Abstract

Hydrogen is increasingly considered as a clean and reliable energy carrier, particularly for meeting peak energy demand. Due to its low density, substantial storage capacities beyond surface-based containers are required. Underground hydrogen storage (UHS) has emerged as a promising solution. Among potential geological formations, saline aquifers offer significant advantages due to their widespread availability, large storage capacity, and relatively low microbial activity. In this study, we utilize numerical simulation to evaluate the feasibility of UHS in an unproductive saline formation within a nearly-depleted hydrocarbon reservoir in Louisiana. To the best of our knowledge, this is the first UHS feasibility study in a Louisiana saline formation/aquifer. Although Louisiana is a leading national energy provider and has hosted several studies and projects on CO2 storage in its geological saline formations, UHS has not yet been explored. Therefore, investigating the viability of UHS in a Louisiana saline formation is needed, which is the goal of this work. First, we develop a geological model of the target formation using Petrel. Data from raster well logs – available in the Louisiana Strategic Online National Research Information System (SONRIS) – are used to delineate sand tops and retrieve other petrophysical parameters. The model considers porosity and permeability heterogeneity where four sand facies are identified. Then, we present a series of reservoir simulation cases using CMG-GEM to investigate the impact of several reservoir parameters and operational conditions on the UHS performance and hydrogen recovery. These parameters include well placement, cushion gas type, cushion-to-working gas rate ratio, target injection and production rates, and hysteresis and dissolution trapping. The base scenario involved cyclic hydrogen injection and production via the same well without cushion gas injection. Results reveal that although target production rates were achieved over cycles, they could not be sustained over the whole production period due to reservoir pressure depletion and gravitational segregation. Relocating the production well up-dip significantly improves hydrogen recovery by 46.0 % when compared to the base case. The use of alternative cushion gases such as nitrogen, carbon dioxide, and methane is assessed to reduce hydrogen losses in maintaining reservoir pressure. Nitrogen showed the best performance, improving hydrogen recovery to 71.8 %, though the co-production of cushion gases. Varying the cushion-to-working gas ratio shows that higher cushion gas volumes enhances reservoir pressure and recovery slightly. Incorporating dissolution and hysteresis effects shows a notable drop in hydrogen recovery, especially due to hysteresis, which results in a 24.0 % overestimation of hydrogen production, if neglected. Finally, modifying the injection/production rate demonstrates that higher rates improve recovery due to better hydrogen mobility and reduced brine permeability. These findings highlight the importance of well placement, cushion gas type and volume, target injection and production rates, and hysteresis and dissolution trappings in simulating and optimizing the UHS performance in saline formations.

Publication Source (Journal or Book title)

International Journal of Hydrogen Energy

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